CO<Subscript>2</Subscript> mitigation in coal gasification cogeneration systems with integration of the shift reaction,CO<Subscript>2</Subscript> absorption and methanol production

Cogeneration of electricity and liquid fuel can achieve higher efficiencies than electricity generation alone in Integrated Gasification Combined Cycle (IGCC), and cogeneration systems are also expected to mitigate CO₂ emissions. A proposed methanol-electricity cogeneration system was analyzed in this paper using exergy method to evaluate the specified system. A simple cogeneration scheme and a complicated scheme including the shift reaction and CO₂ removal were compared. The results show that the complicated scheme consumes more energy, but has a higher methanol synthesis ratio with partial capture of CO₂. In those methanol and electricity cogeneration systems, the CO₂ mitigation is not merely an additional process that consumes energy and reduces the overall efficiency, but is integrated into the methanol production.     

Analysis of CO2 emissions reduction potential in secondary production and semi-fabrication of non-ferrous metals

Industrial sector growth in developing countries requires the provision of alternatives to guarantee sustainable development. Improving energy efficiency and fuel switching are two measures to reduce CO₂ emissions in the industrial sector, with natural gas and low-carbon electricity as the most feasible options in the short term. In this work, a linear programming optimization model has been developed to study the potential of energy efficiency improvement and fuel substitution for CO₂ emissions reduction, at national level in the non-ferrous metals industry. The energy resource/end-use device allocation problem in secondary metal production and semi-fabrication has been modeled. Using this model, the particular case of Colombia, where low-carbon electricity is available, has been studied. By improving energy efficiency, energy use and CO₂ emissions can be reduced significantly, 73% and 72%, respectively, at negative costs. Further CO₂ emissions reductions, up to 88%, are possible with fuel switching to low-carbon electricity, increasing the costs for the energy system; however, cost reductions caused by energy efficiency improvement outweigh cost increments of fuel switching. Benefits achieved with fuel substitution using low-carbon electricity can be lost if hydropower is not available; in such a case, efficient natural gas-fired end-use devices are preferable.     

Achieving emissions reduction through oil sands cogeneration in Alberta’s deregulated electricity market

The province of Alberta faces the challenge of balancing its commitment to reduce CO₂ emissions and the growth of its energy-intensive oil sands industry. Currently, these operations rely on the Alberta electricity system and on-site generation to satisfy their steam and electricity requirements. Most of the on-site generation units produce steam and electricity through the process of cogeneration. It is unclear to what extent new and existing operations will continue to develop cogeneration units or rely on electricity from the Alberta grid to meet their energy requirements in the near future. This study explores the potential for reductions in fuel usage and CO₂ emissions by increasing the penetration of oil sands cogeneration in the provincial generation mixture. EnergyPLAN is used to perform scenario analyses on Alberta’s electricity system in 2030 with a focus on transmission conditions to the oil sands region. The results show that up to 15–24% of CO₂ reductions prescribed by the 2008 Alberta Climate Strategy are possible. Furthermore, the policy implications of these scenarios within a deregulated market are discussed.     

A multiperiod multiobjective framework for the synthesis of trigeneration systems in tertiary sector buildings

This paper develops a multiperiod multiobjective optimization procedure to determine the optimal configuration and operational strategy of a trigeneration system assisted with solar-based technologies and thermal energy storage. The optimization model, formulated as mixed integer linear programming problem, incorporates dynamic operating conditions through time-dependent local climatic data, energy resources, energy demands, electricity prices, and electricity CO₂ emission factors. The methodology is applied to a case study of a residential building in Spain. First, the single-objective solutions are obtained, highlighting their fundamental differences regarding the installation of cogeneration (included in the optimal total annual cost solution) and solar-based technologies (included in the optimal total annual CO₂ emissions solution). Then, the Pareto curve is generated, and a decision-making approach is proposed to select the preferred trade-off solutions based on the marginal cost of CO₂ emissions saved. Additionally, sensitivity analyses are performed to investigate the influence of key parameters concerning energy resources prices, investment costs, and rooftop area. The analyses of the trade-off solutions verify the enormous potential for CO₂ emissions reduction, which can reach 32.3% with only 1.1% higher costs by displacing cogeneration in favor of the heat pump and the electric grid. Besides, with a modest cost increase of 7.3%, photovoltaic panels are incorporated, promoting an even greater CO₂ emissions reduction of 45.2%.     

Experimental study of combustion performances and emissions of a spark ignition cogeneration engine operating in lean conditions using different fuels

This work presents an experimental study describing a six-cylinder spark ignition engine running with a lean equivalence ratio, high compression ratio, ignition delay and used in a cogeneration system (heat and electricity production). Three types of fuels; natural gas, pure methane and methane/hydrogen blend (85% CH₄ and 15% H₂ by volume), were used for comparison purposes. Each fuel has been investigated at 1500 rpm and for various engine loads fixed by electrical power output conditions. CO, CO₂, HC, and NOx emissions values, and exhaust gas temperature were measured. The effect of fuel composition on engine characteristics has been studied. The results show, that the hydrogen addition increased HC emissions (around 18%), as well as performance, whilst it reduced NO_x (around 31%), exhaust gas temperature, CO and CO₂.     

Effects on global CO<Subscript>2</Subscript> emissions when substituting LPG with bio-SNG as fuel in steel industry reheating furnaces—the impact of different perspectives on CO<Subscript>2</Subscript> assessment

The iron and steel industry is the second largest user of energy in the world industrial sector and is currently highly dependent on fossil fuels and electricity. Substituting fossil fuels with renewable energy in the iron and steel industry would make an important contribution to the efforts to reduce emissions of CO₂. However, different approaches to assessing CO₂ emissions from biomass and electricity use generate different results when evaluating how fuel substitution would affect global CO₂ emissions. This study analyses the effects on global CO₂ emissions when substituting liquefied petroleum gas with synthetic natural gas, produced through gasification of wood fuel, as a fuel in reheating furnaces at a scrap-based steel plant. The study shows that the choice of system perspective has a large impact on the results. When wood fuel is considered available for all potential users, a fuel switch would result in reduced global CO₂ emissions. However, applying a perspective where wood fuel is seen as a limited resource and alternative use of wood fuel is considered, a fuel switch could in some cases result in increased global CO₂ emissions. As an example, in one of the scenarios studied, a fuel switch would reduce global CO₂ emissions by 52 ktonnes/year if wood fuel is considered available for all potential users, while seeing wood fuel as a limited resource implies, in the same scenario, increased CO₂ emissions by 70 ktonnes/year. The choice of method for assessing electricity use also affects the results.     

Opportunities and challenges of low-carbon hydrogen via metallic membranes

Today, electricity & heat generation, transportation, and industrial sectors together produce more than 80% of energy-related CO₂ emissions. Hydrogen may be used as an energy carrier and an alternative fuel in the industrial, residential, and transportation sectors for either heating, energy production from fuel cells, or direct fueling of vehicles. In particular, the use of hydrogen fuel cell vehicles (HFCVs) has the potential to virtually eliminate CO₂ emissions from tailpipes and considerably reduce overall emissions from the transportation sector. Although steam methane reforming (SMR) is the dominant industrial process for hydrogen production, environmental concerns associated with CO₂ emissions along with the process intensification and energy optimization are areas that still require improvement. Metallic membrane reactors (MRs) have the potential to address both challenges. MRs operate at significantly lower pressures and temperatures compared with the conventional reactors. Hence, the capital and operating expenses could be considerably lower compared with the conventional reactors. Moreover, metallic membranes, specifically Pd and its alloys, inherently allow for only hydrogen permeation, making it possible to produce a stream of up to 99.999+% purity.For smaller and emerging hydrogen markets such as the semiconductor and fuel cell industries, Pd-based membranes may be an appropriate technology based on the scales and purity requirements. In particular, at lower hydrogen production rates in small-scale plants, MRs with CCUS could be competitive compared to centralized H₂ production. On-site hydrogen production would also provide a self-sufficient supply and further circumvent delivery delays as well as issues with storage safety. In addition, hydrogen-producing MRs are a potential avenue to alleviate carbon emissions. However, material availability, Pd cost, and scale-up potential on the order of 1.5 million m³/day may be limiting factors preventing wider application of Pd-based membranes.Regarding the economic production of hydrogen, the benchmark by the year 2020 has been determined and set in place by the U.S. DOE at less than $2.00 per kg of produced hydrogen. While the established SMR process can easily meet the set limit by DOE, other carbon-free processes such as water electrolysis, electron beam radiolysis, and gliding arc technologies do not presently meet this requirement. In particular, it is expected that the cost of hydrogen produced from natural gas without CCUS will remain the lowest among all of the technologies, while the hydrogen cost produced from an SMR plant with solvent-based carbon capture could be twice as expensive as the conventional SMR without carbon capture. Pd-based MRs have the potential to produce hydrogen at competitive prices with SMR plants equipped with carbon capture.Despite the significant improvements in the electrolysis technologies, the cost of hydrogen produced by electrolysis may remain significantly higher in most geographical locations compared with the hydrogen produced from fossil fuels. The cost of hydrogen via electrolysis may vary up to a factor of ten,d epending on the location and the electricity source. Nevertheless, due to its modular nature, the electrolysis process will likely play a significant role in the hydrogen economy when implemented in suitable geographical locations and powered by renewable electricity.This review provides a critical overview of the opportunities and challenges associated with the use of the MRs to produce high-purity hydrogen with low carbon emissions. Moreover, a technoeconomic review of the potential methods for hydrogen production is provided and the drawbacks and advantages of each method are presented and discussed.     

Multi-objective optimization of biogas systems producing hydrogen and electricity with solid oxide fuel cells

The design of solid oxide fuel cells (SOFC) using biogas for distributed power generation is a promising alternative to reduce greenhouse gas emissions in the energy and waste management sectors. Furthermore, the high efficiency of SOFCs in conjunction with the possibility to produce hydrogen may be a financially attractive option for biogas plants. However, the influence of design variables in the optimization of revenues and efficiency has seldom been studied for these novel cogeneration systems. Thus, in order to fulfill this knowledge gap, a multi-objective optimization problem using the NSGA-II algorithm is proposed to evaluate optimal solutions for systems producing hydrogen and electricity from biogas. Moreover, a mixed-integer linear optimization routine is used to ensure an efficient heat recovery system with minimal number of heat exchanger units. The results indicate that hydrogen production with a fuel cell downstream is able to achieve high exergy efficiencies (65–66%) and a drastic improvement in net present value (1346%) compared with sole power generation. Despite the additional equipment, the investment costs are estimated to be quite similar (12% increase) to conventional steam reforming systems and the levelized cost of hydrogen is very competitive (2.27 USD/kgH₂).     

Sustainable and economic hydrogen cogeneration from nuclear energy in competitive power markets

Hydrogen is becoming the reference fuel for future transportation. However, hydrogen production either directly or indirectly needs to satisfy three criteria: no associated emissions, including CO₂; wide availability; and affordability. Water electrolysis is the only available technology today able to meet the first and second criteria. The third criterion includes costs of electrolysis and electricity. The primary requirements for affordable electrolysis are low capital cost and high utilization. Consequently, the electricity supply must enable high utilization as well as being itself low-cost and emissions-free. The only proven, large-scale source of electricity is evolved nuclear technologies, producing electricity at rates competitive with today's CO₂-emitting, fossil-fueled technologies. As an example, we show sustainable deployment using cogeneration in a typical competitive power market.     

Integration of methane cracking and direct carbon fuel cell with CO2 capture for hydrogen carrier production

Hydrogen fuel production from methane cracking is a sustainable process compared to the ones currently in practice due to zero greenhouse gas emissions. Also, carbon black that is co-produced is valuable and can be marketed to other industries. As this is a high-temperature process, using solar energy can further improve its sustainability. An integrated solar methane cracking system is proposed where hydrogen and carbon products are sent to fuel cells to generate electricity. The CO₂ exhaust stream from the carbon fuel cell is captured and reacted with hydrogen in the CO₂ hydrogenation unit to produce liquid fuels – Methanol and dimethyl ether. The process is simulated in Aspen Plus®, and its energy and exergy efficiencies are evaluated by carrying out a detailed thermodynamic analysis. In addition, a sensitivity analysis is performed on various input parameters of the system. The overall energy efficiency of 41.9% and exergy efficiency of 52.3% were found.     

Using LMDI method to analyze the change of China's industrial CO2 emissions from final fuel use: An empirical analysis

Based on time series decomposition of the Log-Mean Divisia Index (LMDI), this paper analyzes the change of industrial carbon emissions from 36 industrial sectors in China over the period 1998–2005. The changes of industrial CO₂ emission are decomposed into carbon emissions coefficients of heat and electricity, energy intensity, industrial structural shift, industrial activity and final fuel shift. Our results clearly show that raw chemical materials and chemical products, nonmetal mineral products and smelting and pressing of ferrous metals account for 59.31% of total increased industrial CO₂ emissions. The overwhelming contributors to the change of China's industrial sectors’ carbon emissions in the period 1998–2005 were the industrial activity and energy intensity; the impact of emission coefficients of heat and electricity, fuel shift and structural shift was relatively small. Over the year 1998–2002, the energy intensity change in some energy-intensive sectors decreased industrial emissions, but increased emissions over the period 2002–2005. The impact of structural shift on emissions have varied considerably over the years without showing any clear trend, and the final fuel shift increased industrial emissions because of the increase of electricity share and higher emissions coefficient. Therefore, raw chemical materials and chemical products, nonmetal mineral products and smelting and pressing of ferrous metals should be among the top priorities for enhancing energy efficiency and driving their energy intensity close to the international advanced level. To some degree, we should reduce the products waste of these sectors, mitigate the growth of demand for their products through avoiding the excessive investment highly related to these sectors, increasing imports or decreasing the export in order to avoid expanding their share in total industrial value added. However, all these should integrate economic growth to harmonize industrial development and CO₂ emission reduction.     

Reduction of electricity use in Swedish industry and its impact on national power supply and European CO2 emissions

Decreased energy use is crucial for achieving sustainable energy solutions. This paper presents current and possible future electricity use in Swedish industry. Non-heavy lines of business (e.g. food, vehicles) that use one-third of the electricity in Swedish industry are analysed in detail. Most electricity is used in the support processes pumping and ventilation, and manufacturing by decomposition. Energy conservation can take place through e.g. more efficient light fittings and switching off ventilation during night and weekends. By energy-carrier switching, electricity used for heat production is replaced by e.g. fuel. Taking technically possible demand-side measures in the whole lines of business, according to energy audits in a set of factories, means a 35% demand reduction. A systems analysis of power production, trade, demand and conservation was made using the MODEST energy system optimisation model, which uses linear programming and considers the time-dependent impact on demand for days, weeks and seasons. Electricity that is replaced by district heating from a combined heat and power (CHP) plant has a dual impact on the electricity system through reduced demand and increased electricity generation. Reduced electricity consumption and enhanced cogeneration in Sweden enables increased electricity export, which displaces coal-fired condensing plants in the European electricity market and helps to reduce European CO₂ emissions. Within the European emission trading system, those electricity conservation measures should be taken that are more cost-efficient than other ways of reducing CO₂ emissions. The demand-side measures turn net electricity imports into net export and reduce annual operation costs and net CO₂ emissions due to covering Swedish electricity demand by 200 million euros and 6 Mtonne, respectively. With estimated electricity conservation in the whole of Swedish industry, net electricity exports would be larger and net CO₂ emissions would be even smaller.     

Energetic and exergetic analysis of a biomass-fueled CCHP system integrated with proton exchange membrane fuel cell

As a high-efficiency and eco-friendly way of energy conversion, fuel cell has received much attention in recent years. A novel residential combined cooling, heating and power (CCHP) system, consisting of a biomass gasifier, a proton exchange membrane fuel cell (PEMFC) stack, an absorption chiller and auxiliary equipment, is proposed. Based on the established thermodynamic models, the effects of operating parameters, biomass materials type and moisture content on the system performance are closely investigated. Overall system performance is then compared under four different operating modes. From the viewpoints of energy utilization and CO₂ emissions, the CCHP mode has the best performance with corresponding energy efficiency of 57.41% and CO₂ emission index of 0.516 ton/MWh. Exergy analysis results suggest that the optimization and transformation on the gasifier and PEMFC stack should be encouraged. Energy and exergy assessments in this research provide pragmatic guidance to the performance improvement of the integrated CCHP systems with PEMFC. This research also achieves a reasonable combination of efficient cogeneration, green hydrogen production and full recovery of low grade waste heat.     

Evaluating the role of cogeneration for carbon management in Alberta

Developing long-term carbon control strategies is important in energy intensive industries such as the oil sands operations in Alberta. We examine the use of cogeneration to satisfy the energy demands of oil sands operations in Alberta in the context of carbon management. This paper evaluates the role of cogeneration in meeting Provincial carbon management goals and discusses the arbitrary characteristics of facility- and product-based carbon emissions control regulations. We model an oil sands operation that operates with and without incorporated cogeneration. We compare CO₂ emissions and associated costs under different carbon emissions control regulations, including the present carbon emissions control regulation of Alberta. The results suggest that incorporating cogeneration into the growing oil sands industry could contribute in the near-term to reducing CO₂ emissions in Alberta. This analysis also shows that the different accounting methods and calculations of electricity offsets could lead to very different levels of incentives for cogeneration. Regulations that attempt to manage emissions on a product and facility basis may become arbitrary and complex as regulators attempt to approximate the effect of an economy-wide carbon price.     

Modeling of current and future energyintensity and greenhouse gas emissions ofthe Lebanese industrial sector: assessmentof mitigation options

Greenhouse gas emissions in Lebanon mainly come from energy activities, which are responsible for 85% of all CO₂ emissions. The CO₂ emissions from energy use in manufacturing industries and construction represent 24% of the total emissions of the energy sector. Lebanese manufacturers' accounted for 39.15 million gigajoules of fuel consumption for heat and power generation in 1994, including both fuel used directly and fuel burned remotely to generate electricity used in the sector. In addition to being processed by combustion, CO₂ is generated in calcining of carbonates in the manufacture of cement, iron and glass. Electricity, the most expensive form of energy, represented 25.87% of all fuel used for heat and power. Residual fuel oil and diesel, which are used mainly in direct combustion processes, represent 26.85 and 26.55% of all energy use by industry, respectively. Scenarios for future energy use and CO₂ emissions are developed for the industrial sector in Lebanon. The development of the baseline scenario relied on available data on major plants' outputs, and on reported amounts of fuels used by the industrial sector as a whole. Energy use in industry and the corresponding greenhouse gas (GHG) emissions for Lebanon are projected in baseline scenarios that reflect technologies, activities and practices that are likely to evolve from the base year 1994 to year 2040. Mitigation work targets a 15% of CO₂ emissions from the baseline scenario by year 2005 and a 20–30% reduction of CO₂ emissions by year 2040. The mitigation options selected for analysis are screened on the basis of GHG emissions and expert judgement on the viability of their wide-scale implementation and economic benefits. Using macroeconomic assessment and energy price assumptions, the final estimates of potential GHG emissions and reduction costs of various mitigation scenarios are calculated. The results show that the use of efficient electric motors, efficient boilers and furnaces with fuel switching from fuel oil to natural gas has the largest impact on GHG emissions at a levelized annual cost that ranges from −20 to −5 US$/tonne of CO₂ reduced. The negative costs are indicative of direct savings obtained in energy cost for those mitigation options.     

Modernization of local energy systems

This paper analyzes modernization options for a local energy system, including both demand reduction and supply-related measures. The high-resolution optimization model deeco (dynamic energy, emission, and cost optimization) is extended by developing techniques to support conventional insulation measures, transparent insulation, and switchable transparent insulation. Supply-side technologies include gas-fired boilers, heat pumps, solar collectors, and the cogeneration of heat and electricity. Compared to common practice comprising oil-fired boilers and public grid electricity, gas-fired cogeneration is a favorable option, although sensitive to electricity tariffs. Given the current prices of fossil fuels, extensive retrofitted thermal insulation would reduce CO₂-equivalent emissions by about 20% and increase overall costs by 25%.     

Performance analysis of various hybrid renewable energy systems using battery,hydrogen, and pumped hydro‐based storage units

The aim of this research is to analyze the techno‐economic performance of hybrid renewable energy system (HRES) using batteries, pumped hydro‐based, and hydrogen‐based storage units at Sharurah, Saudi Arabia. The simulations and optimization process are carried out for nine HRES scenarios to determine the optimum sizes of components for each scenario. The optimal sizing of components for each HRES scenario is determined based on the net present cost (NPC) optimization criterion. All of the nine optimized HRES scenarios are then evaluated based on NPC, levelized cost of energy, payback period, CO₂ emissions, excess electricity, and renewable energy fraction. The simulation results show that the photovoltaic (PV)‐diesel‐battery scenario is economically the most viable system with the NPC of US$2.70 million and levelized cost of energy of US$0.178/kWh. Conversely, PV‐diesel‐fuel cell system is proved to be economically the least feasible system. Moreover, the wind‐diesel‐fuel cell is the most economical scenario in the hydrogen‐based storage category. PV‐wind‐diesel‐pumped hydro scenario has the highest renewable energy fraction of 89.8%. PV‐wind‐diesel‐pumped hydro scenario is the most environment‐friendly system, with an 89% reduction in CO₂ emissions compared with the base‐case diesel only scenario. Overall, the systems with battery and pumped hydro storage options have shown better techno‐economic performance compared with the systems with hydrogen‐based storage.     

Cost‐effectiveness analysis of energy efficiency measures in the Swiss chemical and pharmaceutical industry

Energy efficiency improvement is an effective way of reducing energy demand and CO₂ emissions. Although the overall final energy savings potential in chemical industry has been estimated in a few countries, energy efficiency potentials by concrete measures applicable in the sector have been scarcely explored and their associated costs are hardly analyzed. In Switzerland, the production of chemicals and pharmaceuticals exceeds all other industrial sectors in terms of energy use and CO₂ emissions, and it accounted for 22% of the total industry's overall final energy demand and 25% of the CO₂ emissions related to non‐renewable energy sources in 2016. In this study, the economic potentials for energy efficiency improvement and CO₂ emissions reduction in the Swiss chemical and pharmaceutical industry are investigated in the form of energy efficiency cost curves. The economic potential for final energy savings and CO₂ abatement based on energy‐relevant investments is estimated at 15% and 22% of the sector's final energy use and fossil fuel‐related CO₂ emissions in 2016, respectively. Measures related to process heat integration are expected to play a key role for final energy savings. The economic electricity savings potential by improving motor systems is estimated at 15% of the electricity demand by these systems in 2016. The size of economic potential of energy efficiency improvement across the sector decreases from 15% to 11% for 0.5 times lower final energy prices while the size increases insignificantly for 1.5 times higher final energy prices. The additional power generation potential based on Combined Heat and Power plants is estimated at 14 MW for 2016. This study is a contribution to the so far limited international literature on economic energy efficiency measures applicable in this heterogeneous sector and can support policy development. The results for specific costs of energy efficiency measures can also be adapted to other parts of the world by making suitable adjustments which in return may provide useful insights for decision makers to invest in economically viable clean energy solutions.     

Multiobjective optimization for exergoeconomic analysis of an integrated cogeneration system

In this paper, a novel cogeneration system integrating Kalina cycle, CO₂ chemical absorption, process, and flash‐binary cycle is proposed to remove acid gases in the exhaust gas of solid oxide fuel cell (SOFC) system, improve the waste heat utilization, and reduce the cold energy consumed during CO₂ capture. In the CO₂ chemical absorption process, the methyldiethanolamine (MDEA) aqueous solution is utilized as a solvent, and feed temperature and absorber pressure are optimized via Aspen Plus software. The single‐objective and multiobjective optimization are carried out for the flash‐binary cycle subsystem. Results show that when the multiobjective optimization is applied to identify the exergoeconomic condition, the cogeneration system can simultaneously satisfy the high thermodynamic cycle efficiency and also the low product unit cost. The optimal results of the exergy efficiency, product unit cost, and normalized CO₂ emissions obtained by Pareto chart were 75.84%, 3.248 $/GJ, and 13.14 kg/MWhr, respectively.     

High-performance gas–electricity cogeneration using a direct carbon solid oxide fuel cell fueled by biochar derived from camellia oleifera shells

Direct carbon solid oxide fuel cells (DC-SOFCs) are promising for generating electricity cleanly and efficiently from solid carbon fuel. Biochar from Camellia oleifera shells is used in a tubular electrolyte-supported 2-cell DC-SOFC stack with a yttrium-stabilized zirconia (YSZ) electrolyte and silver–gadolinium-doped ceria (Ag-GDC) as symmetrical electrodes. The DC-SOFC exhibits comparable electrical performance to the same cell operated on hydrogen fuel and can cogenerate CO and electricity when fueled by biochar. The gas–electricity cogeneration performance of the DC-SOFC is tested under constant-current discharge in terms of electrical power output, CO output rate and purity, electrical conversion efficiency, and gas–electrical cogeneration conversion efficiency. The purity of the output CO can reach more than 80%. Considering the chemical energy of CO a part of the output power, the energy conversion efficiency of >70% is attained. Furthermore, the gas–electricity cogeneration performance is relatively stable before the biochar fuel is exhausted.